Hydrocarbon-producing wells are often stimulated by hydraulic fracturing treatments. In hydraulic fracturing treatments, a viscous fracturing fluid, which also functions as a carrier fluid, is pumped into a producing zone to be fractured at a rate and pressure such that one or more fractures are formed in the zone. Particulate solids for propping open the fractures, commonly referred to in the art as “proppant,” are generally suspended in at least a portion of the fracturing fluid so that the particulate solids are deposited in the fractures when the fracturing fluid flows back as a low viscosity broken fluid to the surface. The proppant deposited in the fractures functions to prevent the fractures from fully closing and maintains conductive channels through which produced hydrocarbons can flow.
After the fracturing fluid, which is the carrier fluid for the proppant, deposits the proppant in the fracture, the fracture closes on the proppant. Such partially closed fractures apply pressure on proppant particles. For this purpose, the interstitial space between particles should be sufficiently large, yet the particles should possess the mechanical strength to withstand closure stresses to hold fractures open after the fracturing pressure is withdrawn. Thus, for instance, large mesh proppants exhibit greater permeability than small mesh proppants at low closure stresses, but they will mechanically fail and thereby produce very fine particulates (“fines”) at high closure pressures.
High production wells often experience proppant flow back after hydraulic fracturing operations. Flow back is more severe in high production wells. If the proppant flows back into the well bore, then the width of the fracture decreases and thereby limits the flow channel conductivity, impairing the effectiveness of the fracturing treatment. In addition, produced proppant also erodes production equipment leading to economic loss attributed to repairs and treatment processes.
It is generally accepted that an unconfined compressive strength of about 150 psi is sufficient to control proppant flow back in high producing wells with moderate temperatures (Applications of Curable Resin-Coated Proppant, Production Engineering, November 1992, 343-349). For a consolidated proppant pack to succeed over the long term, the consolidation strength must be maximized yet be flexible enough to withstand repeated stress cycles that occur during production in reservoir conditions.
In this context, natural sand is widely used as a proppant in reservoirs with lower overburden stresses. Yet, because natural sand is economical and plentiful in supply, it is increasingly used as a proppant in reservoirs with intermediate to higher overburden stresses. Consequently, natural sand used in these more extreme conditions gives rise to the problems discussed above. Since natural sand cannot be used effectively for reservoirs with intermediate and higher overburden stresses, man-made proppants are used. However, even man-made proppant gives rise to fines generation under higher over burden stresses.
To mitigate the foregoing issues, those who are skilled in the art can employ curable resin coatings on proppant particles. Some resin systems can maximize bonding between proppant particles and maximize consolidation strength of the proppant pack whilst maintaining proppant conductivity.
Against this background, natural sand poses a difficult challenge as a proppant: it is naturally irregular in shape and, hence, it is difficult to achieve uniform coating of sand particles. Non-uniform coating on natural sand also decreases the overall strength of the proppant and allows the generation of fines. It is difficult moreover to design a single resin system that is useful for both low and high temperature wells.